Tube-wave seismic imaging

ABSTRACT

The detailed analysis of cross well seismic data for a gas reservoir in Texas revealed two newly detected seismic wave effects, recorded approximately 2000 feet above the reservoir. A tube-wave ( 150 ) is initiated in a source well ( 110 ) by a source ( 111 ), travels in the source well ( 110 ), is coupled to a geological feature ( 140 ), propagates ( 151 ) through the geological feature ( 140 ), is coupled back to a tube-wave ( 152 ) at a receiver well ( 120 ), and is and received by receiver(s) ( 121 ) in either the same ( 110 ) or a different receiving well ( 120 ). The tube-wave has been shown to be extremely sensitive to changes in reservoir characteristics. Tube-waves appear to couple most effectively to reservoirs where the well casing is perforated, allowing direct fluid contact from the interior of a well case to the reservoir.

STATEMENT REGARDING FEDERAL FUNDING

This invention was made with U.S. Government support under ContractNumber DE-AC03-76SF00098 between the U.S. Department of Energy and TheRegents of of the University of California for the management andoperation of the Lawrence Berkeley National Laboratory. The U.S.Government has certain rights in this invention.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to co-pending international patentapplication number PCT/US2004/026356 filed Aug. 13, 2004, entitled“Tube-wave Seismic Imaging Method and Apparatus”, which in turn claimspriority to U.S. provisional patent application No. 60/495,586 filedAug. 15, 2003, entitled “Tube-wave Seismic Imaging Method andApparatus”, both of which are hereby incorporated by reference.

REFERENCE TO A COMPUTER PROGRAM

Not Applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to seismic imaging, and more particularlyto seismic imaging with tube-wave excitation and detection.

2. Description of the Relevant Art

U.S. Pat. No. 6,591,193, entitled “Method and apparatus for acquiringoffset checkshot survey data using tube-wave conversion”, incorporatedherein by reference, discloses a method for acquiring offset checkshotsurvey data for the subsurface region in the vicinity of a fluid-filledwell, said method comprising the steps of: deploying an acousticreceiver at a known depth in said well; determining the tube-wavetraveltime from said acoustic receiver to a tube-wave conversion pointlocated in said well; generating a seismic signal at a source locationthat is laterally offset from said well; measuring the total traveltimeof said seismic signal along a ray path from said source location tosaid tube-wave conversion point and then through said fluid to saidacoustic receiver; and subtracting said tube-wave traveltime from saidtotal traveltime to determine the seismic signal traveltime from saidsource location.

Tube-waves have traditionally been regarded as a source of highamplitude noise in borehole seismic data, and great effort typicallygoes into their suppression and elimination from recordings. Tube-waveshave very large amplitudes and can propagate long distances withoutsubstantial decay. A tube-wave is an interface wave for a cylindricalinterface between two media, typically a borehole fluid and surroundingelastic rock. Borehole waves were described by Lamb and were observed inthe early twentieth century, as summarized by White. Using trapped (orguided) mode analysis, the classic tube-wave can be seen as the lowestorder trapped mode. Higher order modes may be generated depending onwave propagation material properties and source frequency. Thefundamental mode is usually referred to as a Stoneley wave. Some workhas been done to analyze tube-wave attributes in order to evaluate rockproperties. The conversion of tube-waves into a coal seam trapped modeswas reported by Albright and Johnson.

BRIEF SUMMARY OF THE INVENTION

This invention provides for a method for seismic imaging usingtubewaves, the method comprising the steps of: a) transmitting an inputtube-wave waveform down a transmitter borehole; b) receiving a signaltube-wave waveform from a receiver borehole; and c) digitally processingsaid signal tube-wave waveform to produce a seismic image of ageological mass disposed between said transmitter and receiverboreholes.

The method above may further comprise the step of coupling either orboth of said borehole tubewaves to said geological mass.

The methods above may preferably be used wherein said receiving stepsignal tube-wave waveform occurs at least 3 times later than the arrivalof an initial P wave through said geological mass in traditional seismicimaging.

The method tube-wave analysis and seismic image generation steps abovemay further comprise the step of controlling an oil or gas fielddisposed in said geological mass based on said seismic image.

An apparatus for seismic imaging using tubewaves may be constructed thatimplements the methods described above.

In an alternate embodiment, an apparatus for seismic imaging usingtubewaves as described above may be constructed, the apparatuscomprising: a) a transmitter borehole for transmitting an inputtube-wave waveform; b) a receiver borehole for receiving a signaltube-wave waveform; and c) a seismic image of a geological mass disposedbetween said transmitter and receiver boreholes produced by digitallyprocessing said signal tube-wave waveform.

The apparatus above may further comprise: a) a transmitter tube-waveconverter, b) wherein said transmitter tube-wave converter converts saidinput tube-wave waveform and couples said input tube-wave waveform tosaid geological mass disposed between said transmitter and receiverboreholes.

The apparatus above may still further comprise: a) a receiver tube-waveconverter, b) wherein said receiver tube-wave converter converts: i) awave in said geological mass disposed between said transmitter andreceiver boreholes, ii) wherein said wave has originated from said inputtube-wave waveform coupled to said geological mass disposed between saidtransmitter and receiver boreholes.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The invention will be more fully understood by reference to thefollowing drawings, which are for illustrative purposes only:

FIG. 1 depicts the data acquisition scheme used for the Stratton crosswell experiment, where: sources and receivers were placed at the upperlow-velocity layers V2, V5 and V12; the reservoir layers are below thedepth of 5100 ft; and all the wells had packers.

FIGS. 2A-C are single shot gathers in 50-100 Hz frequency band for thereceiver well Ward 145, respectively showing that trace sets recorded inV2, V5 and V12 contain high amplitude slower arrivals (wavetrains)W1-W6.

FIGS. 3A-C are respectively the same input data as was used for FIGS.2A-C, but filtered at higher 100-160 Hz frequency band.

FIGS. 4A-C are stacked frequency spectra, as functions of time, for thetraces respectively recorded in V2, V5 and V12 layers.

FIGS. 5A-C are stacked cross-correlations of traces with W1 waveform,where low band pass filtered (50-100 Hz, upper curves) and high bandpass filtered (100-160 Hz, lower curves) data produce the same peakpositions.

FIG. 6 shows a comparison of guided wave energy of the first train withporosity and saturation taken from well logs.

FIG. 7 show a logarithmic plot of determinants as function of velocityV_(tw) at a frequency of 90 Hz frequency, where: notches indicatetube-wave propagation velocities, and vertical lines indicate the wavetrain velocities of W1-W6 measured in the field experiment. Each bondingset is represented by the fundamental m=0 mode (thick solid lines) andfirst m=1 mode (thin solid line). The parameters of model 4 gave thebest fit.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Abstract

The analysis of crosswell seismic data for a gas reservoir in Texasrevealed two newly detected seismic wave effects, recorded 2000 feetabove the reservoir. The first seismic effect is that the dominant latephases on the records are the tube-waves generated in the source welland later converted into laterally propagating waves through thereservoir in gas/water saturated layers, which convert back totube-waves in the receiver well. The tube-waves in the receiver well maybe detected using traditional seismic equipment. The tube-wave trainshowed good correlation with multilayered reservoir zone structure,suggesting that the recorded wave field has strong dependence on thereservoir parameters. The second seismic effect is that the recordedfield is composed of multiple, relatively low-velocity, tube-waves. Themodeling results suggest that imperfect cementation is the likely causeof this phenomenon.

Introduction

Tube-waves are traditionally regarded as a source of high amplitudenoise in borehole seismic data. Substantial effort typically goes intotube-wave suppression and elimination from recordings. Tube-waves havevery large amplitudes and can propagate long distances withoutsubstantial decay. A tube-wave is an interface wave for a cylindricalinterface between two media, typically a borehole fluid and surroundingelastic rock. Borehole waves were described by Lamb and were observed inthe early twentieth century, as summarized by White. Using trapped (orguided) mode analysis, the classic tube-wave can be seen as the lowestorder trapped mode. Higher order modes may also be generated dependingon material properties and source frequency. The fundamental mode istypically called a Stoneley wave in geophysical parlance. Limited workhas been done to analyze tube-wave attributes in order to evaluate rockproperties. The conversion of tube-waves into a coal seam trapped modeswas reported by Albright and Johnson.

Stratton Field Experiment

The Stratton field experiment was designed in order to experimentallydemonstrate the transmission and detection of guided waves inlow-velocity sedimentary layers. The details of data acquisition,processing and low-velocity bed continuity study results can be found inreadily available literature. The objective of the Stratton fieldproject was to establish the feasibility and benefit of using interwellguided seismic waves for the characterization of Gulf Coast gasreservoirs. Target zones were selected based on geological markers,seismic reflectors, and well logs from the upper Frio Formation at theStratton gas field. It was selected because it is one of the mostextensively studied and well-documented producing oil and gas fields onthe Gulf Coast.

The Stratton field consists mainly of sandstones and shales of the FrioFormation with velocity contrasts on the order of 10% to 20%. Threelow-velocity intervals were identified, from top (closest to thesurface) to bottom (deepest), as the V2, V5, and V12 shale zones, andwere recognizable in all the wells.

Referring now to FIG. 1, three wells are diagrammatically indicated 100,which are the wells used to conduct the interwell logging experimentsand are located in almost the same vertical plane. The data werecollected in the receiver wells Ward 159(130) and Ward 145 (120), whilesources were placed in the well Ward 151 (110) between the receiverwells at three positions, corresponding to the centers of target layersV2(111) at 3816 ft (forming data set A145), V5 (112) at 4133 ft (formingdata set B145) and V12 (113) at 4570 ft (forming data set C145). Thesource was Texaco's multiple air gun system, a tool comprised of threeair guns spaced 27 inches apart, which are fired simultaneously witheach shot. Receivers were also clustered about the V2 (131), V5(132),and V12 (133) locations in Ward 159 with sensors at separationsdescribed further below.

A tube-wave (150) is initiated in a source well (110) by a source (111),travels in the source well (110), is coupled to a geological feature(140), propagates (151) through the geological feature (140), is coupledback to a tube-wave (152) at a receiver well (120), and is and receivedby receiver(s) (121) in either the same (110) or a different receivingwell (120).

The guided-wave signatures were related to targets arriving in the0.6-0.8 s time interval. The observed seismic data indicate the presenceof trapped energy in low velocity shale markers between wells 145 and151. Guided waves in the form of leaky modes are excited, transmitted,and detected in the low-velocity shale markers at a well separation of1730 ft (527 m) (not shown in FIG. 1). Dispersion analysis, modeling,frequency-amplitude depth curves, well logs, and lithologicalinformation all support the results. Due to an unusually large interwelldistance in the crosswell system the overall data quality was poor. Justtwo shots were used for stacking the data because the release of airbubbles into the borehole fluid rapidly reduced the coupling between airgun source and the formation, producing about 40% of elastic wave energycompare to a previous shot. The strongest phases in the records, whichwere arriving later then 0.8 s were not interpreted at the time, sincethey were out of the scope of the experiment goals.

Data sets

The three data sets A145, B145 and C145 consist of 46 records each fromthe receivers positioned across the target layers. The upper 7 receivershad a 10 ft spacing interval, while the next 33 receivers had 2 ftspacing and the lower 6 receivers again had 10 ft spacing interval. Thewhole length of the receiver line for the well Ward 145 (120) was 170 ftand had the best data quality compared to the data sets A159, B159 andC159 obtained in the well Ward 159, where 3-component geophones wereused. The recorded signal frequency was up to 300 Hz in the well Ward145 and up to 100 Hz in the far well Ward 159. The Ward 159 data setshad 22 receiver positions with 5 ft spacing covering 115 ft of deptharound each target layer.

While geophones were used in the cemented well Ward 159, the attempt tocement the space around the casing in the well Ward 145 failed, with theresult that there was no good bonding between the casing and theformations above 5100 ft in that well. The hydrophone recording in thatwell had a better signal-to-noise ratio compared to the other well,which is most likely the result of the smaller source-receiver distance.

Referring now to FIGS. 2A-C, the low frequency (50-100 Hz) filteredtraces are respectively shown for data sets A145, B145 and C145. Thesame data sets for the high frequency (100-160 Hz) band are respectivelyshown in FIGS. 3A-C. There is a presence of late high amplitude arrivalsin the data, which is most pronounced at low frequencies. These arrivalsare concentrated in separate wavetrains, which are denoted as W_(k),where the integer index k=1, 2, . . . 6 corresponds to the order ofarrival.

Data Processing

The interpretation of the strong late phases exemplified by thosearriving in the 0.8-2.0 s intervals FIGS. 2A-C and FIGS. 3A-C are ofparticular importance. The relatively small travel time (0.2 s) for thedirect P-wave arrivals suggests that the late phases belong to waveswith long propagation paths and/or rather small velocities. This energywas clearly elsewhere, while the direct P-waves were arriving at 0.2 s.The apparent velocities of the strongest phases around the 1 s arrivaltime were estimated to be in the 1300-1500 m/s range, which correspondto propagating tube-waves.

FIGS. 4A-C respectively show stacked amplitude spectra of tracescomputed with a moving 0.3 s time window for three (A145, B145, andC145) sets. The spectra show the existence of two dominant frequencyranges in the late arriving phases with central values of 60 and 110 Hz.The main features of the panels are the high amplitude wave trains inthe 40-100 Hz interval. The late wave trains with highly similarwaveforms are clearly seen from this data. The traces werecross-correlated with the corresponding first arriving wavetraininterval, which allowed the measurement of the main peak travel timeswith better than 0.01 s accuracy. This interval was 0.7-1.3 s for A145,0.7-1.3 s for A145, and 0.7-1.3 s for A145 datasets. The high(90-100-200-220 Hz) and low (30-40-80-90 Hz) band-pass filtered datareveal practically the same results (FIG. 5), which suggests negligiblylow dispersion in the frequency band under consideration. The measuredtravel times for the strongest central peaks are given below in Table 1and represent upward propagating waves of varying velocities.

TABLE 1 Picked travel times [s] for the maximum energy phases. Receivingwells −> Ward 159 Ward 151 Recorded Wave Wave Wave Wave Wave Wave Wavewaves 1 1 2 3 4 5 6 Layer V2 at 1.17 1.055 1.605 — — — — 3816 ft LayerV5 at 1.04 0.92 1.32 1.75 — — — 4133 ft Layer V12 at 0.86 0.73 0.9651.19 1.115 1.64 1.875 4570 ft

The high degree of correlation between different wave trains W_(k)allows us to assume a constant frequency-independent propagationvelocity along the well. Evaluation of these velocities is done inseveral steps. First, the travel times obtained from well Ward 159 areused to determine the tube-wave velocity v_(c) in the cemented wells,yielding v_(c)=1460 m/s. Then, the velocities v_(k) of the first threek=1, 2, 3 wave-trains recorded in at least two of the target layers aredetermined from the equationΔt _(ij) ^((k)) ≡t _(i) ^((k)) −t _(j) ^((k))=(h _(i) −h _(j))(1/v_(k)+1/v _(c)),   (1)where t_(l) ^((k)) are the recorded travel times for a wave k at atarget layer l, and h_(l) is the depth of that layer. This allows us toevaluate the velocities for the three fastest waves and obtain thevalues v₁=1365 m/s, v₂=470 m/s, and v₃=288 m/s. In order to determinethe depth of origin of slow wave generation, it is assumed that wavesrecorded in Ward 145 originated at the same depth h_(o), and for anytarget layer i=1, 2, 3 the following equation can be used:Δt _(i) ^((eq)) ≡t _(i) ^((e)) −t _(i) ^((q))=(h _(o) −h _(i))(1/v_(e)−1/v _(q))   (2)where indexes e and q indicate one of three recorded waves. All fivepossible combinations of waves (since the layer A has just two recordedwaves) give very close values averaging at h_(o)=5110 ft and varyingwithin a 12 ft range. This value almost coincides with the 5115 ft depthof the well packer. In all of the following evaluations, the packerlocation is the origin of all tube-wave trains recorded in Ward 145.According to well records at depths below the packer Ward 145 hascementation, and therefore it is assumed that the tube-wave velocity atthose depths is the same as for Ward 154 and Ward 159 and is equal tov_(c)=1460 m/s. Using this assumption, the velocities v_(e) of the otherthree wave trains (k=4, 5, 6) can be estimated using the same equation(2). The results for all tube-wave velocity evaluations are shown inTable 2.

TABLE 2 Tube-wave velocities [m/s]. Cemented wells Non cemented partabove casing in Ward 151 Wave 1 Wave 1 Wave 2 Wave 3 Wave 4 Wave 5 Wave6 1460 1365 470 288 207 162 132

The almost perfect lateral homogeneity of the formation permits theinterpretation of the wave propagation of late arrivals as consisting ofthree-leg paths. The wave propagates downward as a regular tube-wave,then converts into a horizontally propagating wave along someseismically conductive layer and after reaching the receiver well itpropagates upwards, splitting into a set of at least six waves ofdifferent velocities at packer depth. The depth h_(g) and velocity v_(g)of this horizontal layer may be estimated by solving two equations ofthe formt _(i) ^((w))=(2h _(g) −h _(o) −h _(i))v _(c) +d _(w) /v _(g)+(h _(o) −h_(i))/v ₁,   (3)where t_(i) ^((w))is the travel time of a first arriving tube-wave atboth receiver wells (w=159, 145), and d_(w) is the distance betweensource and receiver wells (d₁₅₉=2740 ft., d₁₄₅=1730 ft.). The finelayered structure of the formation makes it anisotropic for wavepropagation. The horizontal propagation velocity in layer g can beexpressed in the form v_(g)=v_(v)·a, where v_(v) is the mean velocitytaken from log data and a is some unknown constant. Three independentestimates for each target layer i=A, B, C gave the values h_(g)=5717 ft.and a=0.63. After obtaining these estimates, equation (3) can be used tomap the recorded seismic phases from the time to the depth scale. FIG. 6shows a comparison of guided wave energy of the first train withporosity and saturation taken from well logs.Tube-Wave Modeling

A solution for axial wave propagation in a layered cylinder is exploredin order to explain the observed phenomena of tube-wave splitting. Thesolution is exact and expressed in form of an independent mode serieswith integer index m. It can be used for any layered model withcylindrical symmetry when the material parameters for each layer arehomogeneous. The boundary conditions can be either welded or sliding,where just the normal stresses and displacements are continuous. Thedetails of the solution are given below in Appendix A. For any givenfrequency ω and mode index m the tube-wave velocities v_(tw) ^((m)) werefound as the real roots of Δ_(m)(v_(tw) ^((m)),ω)=0, where Δ_(m)(v_(tw)^((m)), ω) is the determinant of a corresponding boundary conditionproblem (see Appendix B below for a discussion of the Boundary ValueProblem). The root search interval is bounded below 1500 m/s, thepropagation velocity of compressional waves in water.

The primary purpose of the modeling is the explanation of the sixdifferent tube-wave propagation velocities found in the Strattonexperiment data. The diameter of the drill bit for this well was 25 cmand the diameter of the steel casing was 5 mm. These values, as well asthe known material parameters for water, steel casing and the outer rockformation were kept unchanged. The quality of bonding between the casingand the outer rock in receiver well Ward 145 is under investigationbecause this well is not cemented above the packer at 5100 ft. The wellwas drilled before 1980 and it is most likely that the space between thecasing and the formation was filled by fragments of shale and sandstoneas a result of sedimentation and accumulation of broken and washed outrock material. This material will be henceforth referred to as “gauge”,implying that it represents a poorly consolidated, liquid saturatedmixture of sand and shale that contains gas, as the formation has somegas bearing layers. Such formations are known to have very slow P- andS-wave propagation velocities.

Several different models were used in an attempt to match the observedtube-wave data, including different types of space fillings around thecasing: all possible combinations of low velocity gauge, which hadeither welded or sliding contacts with adjacent layers, and could alsohave thin liquid intermediate skin layers that separate gauge fromcasing or rock. The material parameters and sizes of the models aregiven in Table 3. Roots were found for the first two harmonics m=0, 1 .The results of these model computations suggest that the velocities ofwave trains W₂ and W₃ are practically equal to the compressional andshear velocities of the gauge. This conclusion is supported by a typicalvalue of v_(s)/v_(p) ratio equal to 0.62 for these two waves, and alsoby a perfect fit for the fastest velocity of W₁. The thicknesses of theliquid layers had strongest impact on the velocities of W₄, W₅ and W₆,and were varied to find the best fit. The most interesting results forsix out of the ten different models are presented in FIG. 7, and themodels of the bonding are shown in Table 4.

TABLE 3 Parameters of layers for tube-wave modeling Vp Vs DensityMinimal Thickness Material [m/s] [m/s] [g/cm3] radius [cm] [cm] Boreholefluid 1550 0 0.95 0  7   Steel casing 5800 3000 8 7  0.6 Fluid 1550 00.96 7.6  0–1 Gauge 540 280 1.3 7.6–8.6 8.4–6.4 Fluid 1550 0 0.96 15 0–1Cement 3600 1800 2.7 7.6  8.4 Host rock 3600 1800 2.7 16 ∞

TABLE 4 Models of material properties between casing and rock used fortube-wave modeling Model 1 Cement Model 2 Gauge Model 3 Water layer -Gauge Model 4 Gauge - Water layer Model 5 Gauge - Water layer - Gauge

From these results it follows that only Model 4 (bolded above) providesa good fit for all velocities observed in the experiment. This model hassliding contact between casing and the gauge and 7 mm thick liquid skinlayer separating the gauge from the host rock formation. Allgauge-containing models show the fastest tube-wave velocity to be about6% lower than in the cemented case (Model 1). Sliding-welded andwelded-sliding contact models revealed just the main root for thefastest velocity. The sliding-sliding pair gave just two roots for W₅and W₆, but these two roots were absent for the liquid skin containingmodels.

Discussion

The data were recorded at 2000 ft above the depleted gas reservoir.Overall the slow velocities of the tube-waves and the relatively largepropagation distances explain why these waves were traveling 5 to 15times longer than the direct P-waves. Standard cross-well surveys relyon first arriving phases for imaging and thus do not target tube-waves.The log data used for the comparison above were collected 20 yearsbefore the experiment and were obtained before the reservoirexploitation. At the time of the survey most of the gas bearing layerswere depleted and gas had been replaced by water. Therefore, thecomparison of tube-wave amplitudes and saturation data has a qualitativecharacter indicating more the coincidence of peaks rather than theiramplitude. It seems natural that the conversion of tube-waves is moreeffective in saturated rocks that reveal lower velocities and thus trapseismic energy. The mechanism of such conversion requires separatestudy.

The low values of the velocities chosen for gauge can be justified bythe presence of trapped gas, as there were gas bearing layers above thepackers. Even a small amount of gas present in the fluid saturated rockcan dramatically decrease wave propagation velocities. It is also likelythat the gauge was unconsolidated or poorly consolidated, which alsocontributed in lowering of wave propagation velocities within it.

The recorded travel times of the tube-waves consistently indicate thatthe well packer was the source of slow tube-wave generation. The cementpacker represents a strong diffractor that converts the fundamental(fastest) tube-wave into a set of slower waves, exciting an additionalfundamental mode (m=0) related to the gauge and two modes (m=1) relatedto the liquid layer. Such waves for parallel-layer models have beendetected and explained by Chouet, and Ferrazini and Aki. They showedthat waves propagating in a liquid layer between two adjacent halfspaces can have arbitrarily low velocities, which depend on thethickness of the layer. In the case of the cylindrical model, thevelocity of waves in the liquid layers showed detectable sensitivity tochanges as low as 1 mm in the liquid layer thickness. It seems unlikely,though, that liquid skin layer model is an accurate representation ofreality. It seems more likely that small pockets of water trapped in thegauge effectively act as a single thin layer. This is partiallysupported by the presence of low velocity tube-waves for the modelscontaining a liquid layer on either side of the gauge.

Stratton Field Conclusions

Two main wave propagation phenomena were found in the Stratton fieldcrosswell seismic experiment in addition to those found in a previousstudy of directly propagating guided waves. The first phenomenon is thatthe dominant late phases on the records are composed of tube-waves thatare generated in the source wells and subsequently converted into wavespropagating horizontally along the reservoir in gas/water saturatedlayers. The second phenomenon is that in a poorly bonded receiver well aphenomenon of tube-wave mode splitting was found, when six kinds oftube-waves were detected, each having a different velocity. Aspreviously shown, the existence of these waves can be explained by thecontact conditions of the borehole casing with the formation.

Because reservoir waves should be affected by reservoir properties (i.e.porosity, permeability, fracture density and orientation), monitoringbased on use of these waves should allow the detection andinterpretation of reservoir property changes near production boreholes.These effects can be used for the development of new and promisingtechnology for the imaging and monitoring of underground gas, oil andwater reservoirs.

Tube-wave Improvements

Subsequent tube-wave numerical modeling has indicated that well wallperforations themselves play key role in converting and diverting tubewave energy from the well into the geophysical formation. Other factorstested in the cased wells have generally been found to be relativelyinsignificant, and do not appear to contribute to tube-waves going intothe layers when the tubes are not perforated. The role of perforationscan be substituted or increased by placing wave enhancers at thereservoir depths. This is also supported by Stanford field data set, SEG2003.

It was also discovered by modeling that when a perforated formation ismade of fluid-saturated permeable rock (as opposed to caprock) thenconversion and coupling of the energy from tube wave to horizontalenergy is further enhanced. In other words, energy prefers to followfluid-saturated formations to unsaturated ones.

It has also been determined that horizontally traveling signals consistsof certain types of guided/channel waves propagating in low-velocityformations. This fact has far-reaching consequences, since it means thatsignals can travel thousands of feet with much less attenuation thanconventional transmitted and reflected waves. Therefore it makes arealistic large cross-well distance possible for use in oil and gasdeposits spanning onshore and offshore wells.

It was also discovered that tube-wave signal propagation does notnecessarily travel in a straight line between source-receiver well. Ifpropagating reservoir is a curved channel, then guided wave also bendsand follows the channel geometry in transit to the receiver well. Inthis sense, the propagating reservoir appears to act as a waveguide.

Due to the potential of long distance propagation of tube-wave signalsin geophysical structures, it is anticipated that yet anotherapplication of tube-waves is to determine whether the source andreceiver well are connected through the same reservoir compartment orchannel (hence there would be a waveguide connection for the tube-wavesto traverse).

It has been discovered that signal transmission of tube-waves throughgeological structures is sensitive to small changes in the reservoirproperties even of limited spatial extent (or small areas). Thesesensitivities are common to both properties of low-velocity layers, aswell as surrounding higher-velocity layers. Therefore it is expectedthat the transmitted tube-wave signal will also have sensitivity tochanges for both for both low- and high-velocity reservoirs.

It was discovered that most of the currently used acoustic boreholesources generate strong tube waves which can be applied to the tube-wavemethods disclosed herein. Also, the devices used for seismic stimulationmay be used for that purpose, providing reliable, strong and repeatabletube-wave signal originating close to the reservoir zone. Suchapplications may make tube-wave monitoring practical in onshore wellequipped with beam pumps at little cost. Furthermore, the signal doesnot go along the well thus eliminating one leg that is of no interest toreservoir and reduce uncertainty of the method. Still more, the signalis much stronger and therefore ameliorates the signal/noise problem.

It has also been discovered that in realistic formations, the cross-welltube-wave signal is very complex. To unravel the signal it is suggestedthat using a pre-monitoring survey containing a tube-wave suppressor: adevice for minimizing the transmission of tube waves. Attaching thesuppressor to the bottom of the recording array and lowering it down,will effectively cut all tube waves from below the packer, whilepreserve the ones above. Thus, running vertical profiles beforeproduction will allow defined time window sections responsible for eachreservoir unit, and may be so correlated. This makes it possible toperform unambiguous interpretation of the signal at the monitoringstage. Without such pre-monitoring survey it is easy to imagine thatsparse cross-well data would be impossible or exceedingly difficult tointerpret.

It has further been discovered that two different signals may be used:one is tube wave in the tubing fluid, while another is a different tubewave in annulus fluid. One or the other or both can potentially be usedas a tube-wave propagator depending on the well design.

It has been discovered by modeling that presence of any production(permanent or retrievable) packer greatly reduces tube-wave signalamplitudes passing through it, and therefore wells without packers arepreferred for tube-wave applications. Additionally, the presence of apacker in a given well may determine whether annulus or tubingpropagation paths will be the preferred signal path.

It has been further discovered that the absence of cement or poorcementation of wells does not kill the tube-wave signal whereas it doeskill the conventional signal for Vertical Seismic Profiles orconventional cross-well. Therefore it extends tube-wave monitoring toareas where conventional techniques are not applicable.

Tube waves strongly attenuate in the presence of free gas in well fluid.Therefore, tube-wave technology does not immediately appear applicableto fields where gas is present in free form inside the tubing or annulusunless the tube-wave source is close to the perforated section.

It is possible to use a single-well reflection sounding with tube-wavesin addition to cross-well sounding. Technically, one only needs to addseveral receivers in each source well. While there appears to beliterature relating to tube-wave reflection logs, it appears that suchliterature is a qualitative scheme only and does not consider anymonitoring applications.

It was discovered by modeling that signals reflect off the perforatedintervals. This is consistent the theory that a tube-wave is a pressurewave transiting the fluid of a well bore, so a perforation in the wellbore allows for direct hydraulic connection between the tube-wave andthe medium with which to be coupled. The direct hydraulic connection mayalso be interpreted as a new signal source at the location(s) of theperforation(s).

It was discovered that the tube-wave signal varies depending on thepermeability of the perforated formation immediately surrounding thewell, or the gauge. Therefore, a single-well reflection sounding withtube-waves is a way to assess change in permeability and/or skin aroundthe well during production, stimulation etc.

It was discovered that there is a dependency of the signal on thecontent of the perforation. Thus the signal may serve as diagnostics forestimating the perforation quality/content as well as changes in time.

It was discovered that a single well tube-wave survey can allow thedifferentiation between true reservoir changes, and changes related tosource well bore only (and thus unrelated to reservoir).

APPENDIX A

Cylindrical Vector System

The cylindrical vector system used in this paper was previouslyintroduced by Korneev and Johnson. Use of these vectors makesexpressions for the Lamé equation especially simple since theythoroughly imply a special symmetry of the problem. The cylindricalvector system has the formY _(m) ⁰ =Y _(m) e ₃ , Y _(m) ⁺ =Y _(m) e ₁ −Y _(m) e ₂ , Y _(m) ⁻ =Y_(m) e ₁ +Y _(m) e ₂,   (A1)whereY _(m) ≡Y _(m)(φ, z)≡exp^(i(mφ+hz)) , m=0, 1, 2, . . . ,   (A2)and h is the projection of the wavenumber onto the OZ-axis, i=√{squareroot over (−1)}. Vectors e₁, e₂ , e₃ are the natural unit vectors of thecylindrical coordinate system (ρ, φ, z).

The cylindrical vectors of the system in (A1) are orthonormal at anypoint on a cylindrical surface. In the space of vector functions {rightarrow over (f)}(φ),0≦φ≦2π defined on a circle ρ=const., z=const. thevectors (A1) satisfy the following orthogonality relations

$\begin{matrix}{{{\int_{0}^{2\pi}{\left( {Y_{m}^{v} \cdot Y_{m_{1}}^{v_{1}}} \right)\ {\mathbb{d}\varphi}}} = {c^{v}\delta_{{mm}_{1}}\delta_{{vv}_{1}}}},\mspace{14mu}{v = 0},{+ {, -}}} & ({A3})\end{matrix}$where δ_(kl) is equal to 1, when lower indexes are the same, and equalzero otherwise. The normalizing coefficients c^(v)arec⁰=1, c⁺=2, c⁻=2   (A4)

The system (A1) is complete in the sense of convergence in the mean fora Fourier series expansion. This means that any vector function{right arrow over (u)}≡{right arrow over (u)}(ρ, φ, z)={right arrow over(U)}(ρ, φ)expihz   (A5)can be represented in the form

$\begin{matrix}{{\overset{->}{u}\mspace{11mu}\left( {\rho,\varphi,z} \right)} = {\sum\limits_{v}\;{\sum\limits_{m = 0}^{\infty}\;{{f_{m}^{v}(\rho)}\mspace{11mu}{Y_{m}^{v}\left( {\varphi,z} \right)}}}}} & ({A6})\end{matrix}$

The Lamé equation for a homogenous elastic medium is(λ+μ)∇∇·{right arrow over (u)}+∇×∇×ρω²{right arrow over (u)}=0   (A7)where the dependence of the displacement field {right arrow over (u)} ontime t is given by exp(iωt), where ω is the angular frequency. Theparameters λ and μ from (A7) are the Lamé constants, and ρ is thedensity.

Substitution of the form (A6) into equation (A7) and use of theorthogonality property (A3) yields the differential Bessel equations forradial functionsf_(m) ^(v≡f) _(m) ^(v)(ρ):f_(mq) ⁰=d_(mq) ⁰Z_(m)(α_(q)ρ), f_(mq) ^(+=d) _(mq) ⁺Z_(m+1)(α_(q)ρ),f_(mq) ⁻=d_(mq) ⁻Z_(m−1)(α_(q)ρ), q=p,s,   (A8)where Z_(k)(x) is the cylindrical Bessel functions of order k, andd_(mq) ^(v)is an arbitrary constant, which can be determined by solvinga corresponding boundary value problem. The parameter α_(q) fromequation (A8) has two formsα_(p)=√{square root over (ω² /v _(p) ² −h ²)}, . . . α_(s)=√{square rootover (ω² /v _(s) ² −h ²)},   (A9)wherev _(p)=√{square root over ((λ+2μ/ρ)}, and v _(s)=√{square root over(μ/ρ)}  (A10)are the propagation velocities of compressional ({right arrow over(u)}_(p)) and shear ({right arrow over (u)}_(s)) field components.

The simplicity of equations (A8) illustrates the main advantage ofemploying the cylindrical vectors of the form (A1). In all other systemsthe expressions for radial functions would also contain combinations ofBessel functions and their derivatives.

Fields {right arrow over (u)}_(p) and {right arrow over (u)}_(s) satisfythe equationsV ×{right arrow over (u)}_(p)=0, V ·{right arrow over (u)}_(s)=0,  (A11)which leads to the following conditionsd _(mp) ⁺ ≡a _(m) , d _(mp) ⁻ =−a _(m) , d _(mp) ⁰=−2ih/α _(p)   (A12)d _(ms) ⁺ ≡b _(m) , d _(ms) ⁻ =c _(m) , d _(ms) ^(o) =i(b _(m) −c_(m))α_(s) /h   (A13)for the coefficients of equation (A8). Therefore, the fields {rightarrow over (u)}_(p) and {right arrow over (u)}_(s) have the forms

$\begin{matrix}{{\overset{->}{u}}_{p} = {{\sum\limits_{m = 0}^{\infty}{\overset{->}{u}}_{mp}} = {\sum\limits_{m = 0}^{\infty}{a_{m}\left( {{- \frac{2{ih}}{\alpha_{s}}}\begin{matrix}{{{Z_{m}\left( {\alpha_{p}\rho} \right)}\mspace{11mu} Y_{m}^{0}} + {Z_{m + 1}\left( {\alpha_{p}\rho} \right)}} \\{Y_{m}^{+} - {{Z_{m - 1}\left( {\alpha_{p}\rho} \right)}\mspace{11mu} Y_{m}^{-}}}\end{matrix}} \right)}}}} & ({A14}) \\\begin{matrix}{{\overset{->}{u}}_{s} = {\sum\limits_{m = 0}^{\infty}{\overset{->}{u}}_{ms}}} \\{= {\sum\limits_{m = 0}^{\infty}\left( {\frac{{\mathbb{i}\alpha}_{s}\left( {b_{m} - c_{m}} \right)}{h}\begin{matrix}{{{Z_{m}\left( {\alpha_{s}\rho} \right)}\mspace{11mu} Y_{m}^{0}} + {b_{m}{Z_{m + 1}\left( {\alpha_{s}\rho} \right)}}} \\{Y_{m}^{+} + {c_{m}{Z_{m - 1}\left( {\alpha_{s}\rho} \right)}\mspace{11mu} Y_{m}^{-}}}\end{matrix}} \right)}}\end{matrix} & ({A15})\end{matrix}$

For any index m=0, 1, 2, . . . a correspondent component {right arrowover (u)}, v=p, s of equation (A14) or (A15) satisfies the equation ofmotion (A7), and represents an independently propagating harmonic ofthis index.

The expressions for the traction field on a surface ρ=const.

$\begin{matrix}{{t_{\rho}\left( \overset{->}{u} \right)} = {{\lambda{\nabla{\cdot \overset{->}{u}}}e_{1}} + {\mu\mspace{11mu}\left( {{2\frac{\partial\overset{->}{u}}{\partial\rho}} + {e_{1} \times {\nabla{\times \overset{->}{u}}}}} \right)}}} & ({A16})\end{matrix}$expressed through vectors (A1) have the form:

$\begin{matrix}\begin{matrix}{{t_{\rho}\left( {\overset{->}{u}}_{mp} \right)} = {a_{m}\left( {{{- 4}{\mathbb{i}\mu}\;{hZ}_{m}^{\prime}Y_{m}^{0}} + {\alpha_{p}\left( {{{\lambda\left( {1 + {h^{2}/\alpha_{p}^{2}}} \right)}Z_{m}} + {2\mu\;{Z\;}_{m + 1}^{\prime}}} \right)}} \right.}} \\\left. {Y_{m}^{+} + {{\alpha_{p}\left( {{{\lambda\left( {1 + {h^{2}/\alpha_{p}^{2}}} \right)}Z_{m}} - {2\mu\; Z_{m - 1}^{\prime}}} \right)}Y_{m}^{-}}} \right)\end{matrix} & ({A17}) \\\begin{matrix}{{t_{\rho}\left( {\overset{->}{u}}_{ms} \right)} = {{ih}\;{\mu\left( {{b_{m}\left( {Z_{m + 1} + {Z_{m}^{\prime}{\alpha_{s}^{2}/h^{2}}}} \right)} + {c_{m}\left( {Z_{m - 1} - {Z_{m}^{\prime}{\alpha_{s}^{2}/h^{2}}}} \right)}} \right)}}} \\{Y_{m}^{0} + {{\mathbb{i}\alpha}_{s}{\mu\left( {{b_{m}\left( {{2Z_{m + 1}^{\prime}} - {Z_{m}/2}} \right)} + {c_{m}{Z_{m}/2}}} \right)}Y_{m}^{+}} +} \\{{\mathbb{i}\alpha}_{s}{\mu\left( {{b_{m}{Z_{m}/2}} + {c_{m}\left( {{2Z_{m - 1}^{\prime}} + {Z_{m}/2}} \right)}} \right)}Y_{m}^{-}}\end{matrix} & ({A18})\end{matrix}$

In a cylindrical coordinate system, t is given by:

$\begin{matrix}\begin{matrix}{{t_{\rho}\left( {\overset{->}{u}}_{mp} \right)} = {a_{m}\left( {2{\alpha_{p}\left( {{{\lambda\left( {1 + {h^{2}/\alpha_{p}^{2}}} \right)}Z_{m}} + {\mu\left( \;{{Z\;}_{m + 1}^{\prime} - Z_{m - 1}^{\prime}} \right)}} \right)}} \right.}} \\\left. {{Y_{m}e_{1}} - {2{\mathbb{i}\alpha}_{p}{\mu\left( \;{{Z\;}_{m + 1}^{\prime} + Z_{m - 1}^{\prime}} \right)}Y_{m}e_{2}} - {4{\mathbb{i}\mu}\;{hZ}_{m}^{\prime}Y_{m}e_{3}}} \right)\end{matrix} & ({A19}) \\\begin{matrix}{{t_{\rho}\left( {\overset{->}{u}}_{ms} \right)} = {{2\alpha_{s}{\mu\left( {{b_{m}Z_{m + 1}^{\prime}} + {c_{m}Z_{m - 1}^{\prime}}} \right)}Y_{m}e_{1}} + {{\mathbb{i}\alpha}_{s}\mu}}} \\{\left( {{b_{m}\left( {Z_{m} - {2Z_{m + 1}^{\prime}}} \right)} + {c_{m}\left( {Z_{m} + {2Z_{m - 1}^{\prime}}} \right)}} \right)} \\{{Y_{m}e_{2}} + {{ih}\;{\mu\left( {{b_{m}\left( {Z_{m + 1} + {Z_{m}^{\prime}{\alpha_{s}^{2}/h^{2}}}} \right)} +} \right.}}} \\{\left. {c_{m}\left( {Z_{m - 1} - {Z_{m}^{\prime}{\alpha_{s}^{2}/h^{2}}}} \right)} \right)Y_{m}e_{3}}\end{matrix} & ({A20})\end{matrix}$in unit vectors of cylindrical coordinate system. Arguments of theBessel functions and their derivatives are equal to α_(p)ρ for equations(A17) and (A19) and are equal to α_(s)ρ for equation (A18) and (A20).

APPENDIX B

Boundary Value Problem

Consider a model consisting of N cylindrical layers characterized byconstant parameters λ_(n), μ_(n), ρ_(n), n=1, . . . , N and separated byinterfaces r=r_(n), n=1, . . . , N−1. In each layer the elastic wavefield can be expressed through equations (A17), (A18), where the radialfunctions depend on the parameters of each particular layer. In thefluid-bearing layers one has μ_(n)=0 and b_(m)=c_(m)=0. For n=1, thefunction Z_(k) ^((x)) must be finite for r=0 and Z_(k)(x)=J_(k)(x). Forthe outermost medium, the wave field must satisfy the radiationcondition at infinity r=∞, and Z_(k)(x)=H_(k) ⁽²⁾(x). In the cases wherethe intermediate layers are bounded by two interfaces, any twoindependent solutions for the radial functions Z_(k)(x) must be used,thereby doubling the number of coefficients a_(m), b_(m), c_(m) for thatlayer. According to equation (A8) the arguments of the Bessel functionscan be either real or imaginary, depending on the value of the verticalwave number h.

For fluid-solid interfaces the boundary conditions have the form

$\begin{matrix}\begin{matrix}{{{\sum\limits_{i = n}^{n + 1}\;\left( {\overset{->}{u}}^{(i)} \right)_{r}} = 0},} \\{{{\sum\limits_{i = n}^{n + 1}\;\left( t^{(i)} \right)_{r}} = 0},} \\{{\left( t^{({n + 1})} \right)_{\varphi} = 0},} \\{{\left( t^{({n + 1})} \right)_{z} = 0},} \\{{r = r_{n}},} \\{{n = 1},\ldots\mspace{11mu},{N - 1}}\end{matrix} & ({A21})\end{matrix}$while for solid-solid welded contact they are

$\begin{matrix}{{{\sum\limits_{i = n}^{n + 1}\;{\overset{->}{u}}^{(i)}} = 0},{{\sum\limits_{i = n}^{n + 1}\; t^{(i)}} = 0},{r = r_{n}},{n = 1},\ldots\mspace{11mu},{N - 1}} & ({A22})\end{matrix}$

Orthogonality of cylindrical vectors allows to reduce equations (A21)and (A22) to the separate forms

$\begin{matrix}{\begin{matrix}{{{\sum\limits_{i = n}^{n + 1}\;\left( {\overset{->}{u}}_{m}^{(l)} \right)_{r}} = 0},} \\{{{\sum\limits_{i = n}^{n + 1}\;\left( t_{m}^{(i)} \right)_{r}} = 0},} \\{{\left( t_{m}^{({n + 1})} \right)_{\varphi} = 0},} \\{{\left( t_{m}^{({n + 1})} \right)_{z} = 0},} \\{{r = r_{n}},} \\{{n = 1},\ldots\mspace{11mu},{N - 1}}\end{matrix}{and}} & ({A23}) \\{{{\sum\limits_{i = n}^{n + 1}\;{\overset{->}{u}}_{m}^{(i)}} = 0},{{\sum\limits_{i = n}^{n + 1}\; t_{m}^{(i)}} = 0},{r = r_{n}},{n = 1},\ldots\mspace{11mu},{N - 1}} & ({A24})\end{matrix}$for each harmonic m.

For a set of coefficients a_(m) ^((n)), b_(m) ^((n)), c_(m) ^((n)) theconditions (A23) and (A24) give a homogeneous system of linearequations. Taking h to be

$\begin{matrix}{{h = \frac{\omega}{v_{tw}^{(m)}}},} & ({A25})\end{matrix}$where v_(tw) ^((m)) is the vertical phase velocity of the tube waves,the velocities of the propagating tube-waves can be found to be theroots of the equation Δ_(m)(v_(tw) ^((m)),ω)=0, where Δ_(m)(v_(tw)^((m)), ω) is the determinant of the above mentioned linear system.

CONCLUSION

All publications, patents, and patent applications mentioned in thisspecification are herein incorporated by reference to the same extent asif each individual publication or patent application were eachspecifically and individually indicated to be incorporated by reference.

The description given here, and best modes of operation of theinvention, are not intended to limit the scope of the invention. Manymodifications, alternative constructions, and equivalents may beemployed without departing from the scope and spirit of the invention.

1. A method for seismic imaging using tube-waves, the method comprisingthe steps of: a) transmitting an input tube-wave waveform down atransmitter borehole; b) coupling the input tube-wave waveform out ofthe transmitter borehole and into a geological reservoir portion of avolume of a geological mass substantially lateral to the boreholeoutside the transmitter borehole as a converted laterally propagatingsignal tube-wave waveform that propagates as a guided wave along thegeological reservoir portion of the geological mass; c) receiving theconvened laterally propagating signal tube-wave waveform that propagatesthrough the geological mass as a guided wave along the geologicalreservoir portion of the geological mass at a receiver boreholepositioned through the geological reservoir portion of a volume ofgeological mass, and coupling the received converted laterallypropagating signal tube-wave waveform into the receiver borehole as areceived tube-wave waveform; d) providing the receiving and couplingsteps to produce the received tube-wave waveform after arrival of aninitial P wave, said P wave traveling substantially directly throughsaid volume of said geological mass in traditional seismic imaging; ande) digitally processing the received tube-wave waveform to produce aseismic image of said geological reservoir portion of geological massdisposed between said transmitter and receiver boreholes.
 2. The methodof claim 1 further comprising the step of: a) controlling an oil or gasfield disposed in said geological reservoir portion of geological massbased on said seismic image.
 3. The method of claim 1 further comprisingthe step of: a) performing a pre-monitoring survey with a tube-wavesuppressor.
 4. The method of claim 1 wherein the input tube-wave istransmitted as a tube-wave through a tubing fluid in the transmitterborehole.
 5. The method of claim 1 wherein the input tube-wave istransmitted as a tube-wave through an annulus fluid in the transmitterborehole.
 6. The method of claim 1: a) wherein the transmitter boreholecomprises several receivers.
 7. An apparatus for seismic imaging usingtube-waves that implements the methods of claim
 1. 8. A method forseismic imaging using tube-waves, the method comprising the steps of: a)transmitting an input tube-wave waveform down a transmitter borehole; b)coupling the input tube-wave waveform out of the transmitter boreholeand into a geological reservoir portion of a geological masssubstantially lateral to the borehole outside the transmitter boreholeas a converted laterally propagating signal tube-wave waveform thatpropagates as a guided wave along the geological reservoir portion ofthe geological mass; c) receiving the converted laterally propagatingsignal tube-wave waveform that propagates through the geological mass asa guided wave along the geological reservoir portion of the geologicalmass at a receiver borehole positioned through the geological reservoirportion of a volume of geological mass, and coupling the receivedconverted laterally propagating signal tube-wave waveform into thereceiver borehole as a received tube-wave waveform; d) providing thereceiving and coupling steps to produce the received tube-wave waveformafter arrival of an initial P wave, said P wave traveling substantiallydirectly through said volume of said geological mass in traditionalseismic imaging; and e) providing digital means for processing thereceived tube-wave waveform to produce a seismic image of saidgeological reservoir portion of geological mass disposed between saidtransmitter and receiver boreholes.
 9. The method of claim 8 furthercomprising the step of: a) controlling an oil or gas field disposed insaid volume of geological mass based on said seismic image of saidgeological reservoir portion of geological mass disposed between saidtransmitter and receiver boreholes.
 10. The method of claim 8 furthercomprising the step of: a) performing a pre-monitoring survey with atube-wave suppressor.
 11. The method of claim 8 wherein the inputtube-wave is transmitted as a tube-wave through a tubing fluid in thetransmitter borehole.
 12. The method of claim 8 wherein the inputtube-wave is transmitted as a tube-wave through an annulus fluid in thetransmitter borehole.
 13. The method of claim 8: a) wherein thetransmitter borehole comprises several receivers.
 14. An apparatus forseismic imaging using tube-waves that implements the methods of claim 8.15. An apparatus for seismic imaging using tube-waves, the apparatuscomprising: a) a transmitter borehole positioned through a geologicalreservoir portion of a volume of geological mass so an input tube-wavewaveform can be transmitted down the transmitter borehole; b) a firstcoupler that couples the input tube-wave waveform out of the transmitterborehole and into the geological reservoir portion of the geologicalmass outside the transmitter borehole as a converted laterallypropagating signal tube-wave waveform that propagates as a guided wavealong the geological reservoir portion of the geologic mass; c) areceiver borehole positioned through the geological reservoir portion ofa volume of geological mass that receives said converted laterallypropagating signal tube-wave waveform that propagates through thegeological reservoir portion of geological mass as a guided wave alongthe geological reservoir portion and a second coupler that couples thereceived converted laterally propagating signal tube-wave waveform intoa received tube-wave waveform after arrival of an initial P wave, said Pwave traveling substantially directly through said volume of saidgeological mass in traditional seismic imaging; and d) digital means forprocessing the received tube-wave waveform to produce a seismic image ofsaid geological reservoir portion of geological mass disposed betweensaid transmitter and receiver boreholes.